Electro-hydrofracturing using electrically conductive proppants and related methods

ABSTRACT

The present disclosure describes electro-hydrofracturing (E-HF) using electrically conductive proppants and methods for hydraulic fracturing using electrically conductive proppants.

RELATED APPLICATIONS

This Application claims priority under 35 U.S.C. § 119(e) to U.S.Provisional Application No. 63/259,914, filed Aug. 16, 2021, which isincorporated herein by reference in its entirety for all purposes.

GOVERNMENT SPONSORSHIP

This invention was made with Government support under Contract No.DE-AR0001584 awarded by the U.S. Department of Energy. The Governmenthas certain rights in the invention.

FIELD

Disclosed embodiments are related to electro-hydrofracturing usingelectrically conductive proppants and methods for hydraulic fracturingusing electrically conductive proppants.

BACKGROUND

Geothermal or petroleum production well systems may require some degreeof permeability to allow geo-fluid flow to the subsurface. Permeabilityis related to flow rate, heat recovery, petroleum recovery, and volumeof production available from a given resource. Hence, permeability playsan important role in the economics of any given petroleum or geothermalreservoir.

Acid treatment and hydraulic fracturing of the reservoir are the maintechniques used to increase permeability in today's market. Thesemethods are related to Darcy's equation, which shows the relationshipbetween geo-fluid production rate q and pressure differences between thereservoir and the well (P_(res.)−P_(wfp.)):

q=(2πkh/sμB)*(P _(res.) −P _(wfp.))

where, k is the permeability; h is the reservoir thickness; B is theformation volume factor; s is the skin factor; and p is the fluidviscosity.

SUMMARY

In one aspect, a hydraulic fracturing composition is described, thecomposition comprising a transport fluid and a conductive proppantdispersed in the transport fluid, wherein an electrical conductivity ofthe hydraulic fracturing composition is greater than or equal to 100S/m.

In another aspect, a system is described, the system comprising ahydraulic fracturing pump configured to inject a hydraulic fracturingcomposition into a reservoir, wherein the hydraulic fracturingcomposition comprises a transport fluid and a conductive proppant,wherein an electrical conductivity of the conductive proppant is greaterthan or equal to 100 S/m and two or more electrodes configured to applya potential across at least a portion of the reservoir.

In another aspect, a method for fracturing a reservoir is described, themethod comprising injecting a hydraulic fracturing compositioncomprising a transport fluid and a conductive proppant into thereservoir, wherein an electrical conductivity of the conductive proppantis greater than or equal to 100 S/m, applying a potential between afirst portion of the reservoir and a second portion of the reservoir,and fracturing the reservoir between or proximate to the first portionand/or the second portion of the reservoir.

In yet another aspect, a method for characterizing a reservoir isdescribed, the method comprising injecting a hydraulic fracturingcomposition comprising a transport fluid and a conductive proppant intothe reservoir, wherein an electrical conductivity of the conductiveproppant is greater than or equal to 100 S/m, applying electromagneticradiation to the reservoir, sensing one or more signals related to theapplied electromagnetic radiation, and determining one or moreproperties of the reservoir based at least in part on the one or moresignals.

In yet another aspect, a system for characterizing a reservoir isdescribed, the system comprising a hydraulic fracturing pump configuredto inject a hydraulic fracturing composition into a reservoir, whereinthe hydraulic fracturing composition comprises a transport fluid and aconductive proppant, wherein an electrical conductivity of theconductive proppant is greater than or equal to 100 S/m, two or moreelectrodes configured to apply a potential across at least a portion ofthe reservoir, a source of electromagnetic radiation, and a sensorconfigured to receive one or more signals related to the electromagneticradiation.

It should be appreciated that the foregoing concepts, and additionalconcepts discussed below, may be arranged in any suitable combination,as the present disclosure is not limited in this respect. Further, otheradvantages and novel features of the present disclosure will becomeapparent from the following detailed description of various non-limitingembodiments when considered in conjunction with the accompanyingfigures.

BRIEF DESCRIPTION OF DRAWINGS

The accompanying drawings are not intended to be drawn to scale. In thedrawings, each identical or nearly identical component that isillustrated in various figures may be represented by a like numeral. Forpurposes of clarity, not every component may be labeled in everydrawing. In the drawings:

FIG. 1A is a schematic diagram showing a pair of wells with electrodeswithin in an arrangement where each electrode is connected to a pulsedpower system and connected to a power source for providing a potentialacross a reservoir, according to some embodiments;

FIG. 1B is a schematic diagram of a hydraulic fracturing system,according to some embodiments;

FIG. 2A is a schematic illustration of a conductive proppant within ahydraulic fracturing composition, according to some embodiments;

FIG. 2B is a schematic illustration of a core-shell conductive proppantcomprising a conductive shell with a non-conductive core, according tosome embodiments;

FIG. 2C is a schematic illustration of a hydraulic fracturingcomposition comprising conductive proppants and a thickening agent,according to some embodiments;

FIGS. 3A-3F schematically illustrate various stages of hydraulicfracturing using a hydraulic fracturing composition comprising aconductive proppant, according to some embodiments;

FIG. 4 is a flow chart depicting a method of hydraulic fracturing,according to some embodiments;

FIG. 5 shows the mechanical stress at which ˜1750 mD-ft fractureconductivity is maintained for different types of proppants includingsome lightweight ceramics (LWC), intermediate density ceramics (IDC),high density ceramics (HDC), and ultra-high-strength proppants (UHSP),according to some embodiments;

FIG. 6 is plot of the volume of conductive proppant within the hydraulicfracturing composition with respect to the effective conductivity of thehydraulic fracturing composition with slurry electrical conductivitiesfor five values of proppant conductivity shown as functions of volumeconcentrations, according to some embodiments;

FIG. 7 is a diagram showing an exemplary test arrangement fordetermining and improving the efficacy of a low-frequency electricaltreatment system on various core samples from candidate reservoirs,according to some embodiments;

FIG. 8 is a schematic diagram of an exemplary lab scale experimentalarrangement for determining and improving the efficacy of a pulsedelectrical stimulation system on various core samples from candidatereservoirs, according to some embodiments;

FIG. 9 is a schematic diagram of an apparatus for measuring permeabilitybefore and after applying high voltage pulsed discharge on rock samplein the experimental setup of FIG. 8 , according to some embodiments; and

FIG. 10 is a schematic diagram of a pulsed power system, according tosome embodiments.

DETAILED DESCRIPTION

The present disclosure describes hydraulic fracturing compositionsincluding a proppant that is electrically conductive. This disclosurealso describes mapping a subterranean fracture network comprising one ormore subterranean reservoirs.

Conventional hydraulic fracturing techniques include the use of acidichydraulic fracturing compositions. Acidizing technology has advancedthroughout the years, but the basic principle remains the same. Withthis technique, chemical stimulants, primarily hydrochloric andhydrofluoric acids at highly diluted concentrations, between 1 and 15%,injected into the reservoir rock create “wormholes” as the rocksdissolve from the acid treatment. This leads to a reduction in reservoirimpedance and a boost in reservoir fluid flow rate. Since a corrosioninhibitor was developed to protect wells during application, acidizingtechniques have experienced an increase in implementation of up to 400%.However, at high temperatures and in highly consolidated formations,acid penetration is limited, resulting in short conductive flow paths.Additionally, it is not possible to collect back all the injectedtreatment fluids, and thus, some of the acid will remain in theformation after the treatment is completed. Undissolved particles maybuild up in the well, resulting in a reduction in production flow.Acidizing remains less regulated than other techniques, though severalstates have proposed legislation and regulations.

Hydraulic fracturing is commonly used and creates long, open, conductivechannels as fluids are pumped into the reservoir. This chemical mixtureof water and a proppant (e.g., sand) is used to prevent cracks fromclosing after the pressure is released in the reservoir. In someinstances, gels are used when the low viscosity of water makes itdifficult for proppant transport. Gel residues are prone to stay in theformation and cause mineral precipitation leading to sand production inthe well. While hydraulic fracturing is economically less costly thanacidization, this technique is commonly associated with an increase inseismic activity near the wellbore region, rendering it disadvantageousand controversial in certain instances.

The effort required to treat reservoirs with acidized water, fracturesand, as well as the operation and maintenance challenges associatedwith these techniques and the costs of diesel generators in poweringassociated fluid pumps, renders existing techniques to increasereservoir permeability environmentally hazardous, expensive, andtime-consuming. In addition to more typical fracturing techniques,electrical based fracturing methods may also be used to stimulate areservoir. However, the Inventors have recognized that prior electricalbased fracturing methods have tended to result in fracturing that isrelatively localized adjacent to the electrodes used to implementelectrical induced fracturing. A more environmentally friendly andefficient technique to increase the rock permeability of reservoirs ishighly desirable.

The Inventors have recognized and appreciated that the fracturingability of a hydraulic fracturing fluid used during an electrical basedfracturing technique may be increased by the inclusion of one or moreelectrically conductive materials, such as additives and/or proppants,within the fracturing fluid. In contrast, existing techniques forhydraulic fracturing often include sand as a proppant in order tomaintain open fractures. However, sand is electrically non-conductiveand hence cannot contribute to the conductivity of the fracturing fluidor the conductivity of the reservoir as a whole. Thus, the Inventorsdiscovered that by including one or more electrically conductivematerials and/or additives within a fracturing fluid, the conductivityof the hydraulic fracturing fluid can be increased. Advantageously, byincreasing the conductivity of the hydraulic fracturing fluid, thefracturing ability of the electrical stimulation can be increased.Without wishing to be bound by any particular theory, it is believedthat increasing the conductivity of the hydraulic fracturing fluid withthe inclusion of conductive proppants and/or other additives allows forincreased Joule heating across a larger area of a formation when apotential is applied to the hydraulic fracturing fluid comprising theconductive proppant. By increasing the Joule heating of the fracturingfluid when a voltage is applied, more fractures and/or larger portionsof fractures may be opened to a desired degree to stimulate reservoirproduction. In some embodiments, after heating, a cooling fluid of alower temperature (e.g., less than or equal to 20° C.) than the heatedhydraulic fracturing fluid may be injected into the reservoir. Thecontrast between heating and cooling may advantageously furtherfacilitate fracturing, by facilitating rapid expansion and/orcontraction of subterranean earth near the heated reservoir.

The Inventors have also recognized that it may be difficult to determinewhere to apply electro-hydraulic fracturing within a reservoir usingconventional characterization techniques due to the difficulty inimaging the different features of a reservoir. Accordingly, theInventors have also appreciated that hydraulic fracturing fluidincluding a conductive material, such as a proppant, can be used to mapa fracture network within and/or proximate to a reservoir. As thehydraulic fracturing composition comprising the conductive material isinjected into a reservoir, some portions of the reservoir, and theresulting formed fractures, may be infiltrated by the hydraulicfracturing composition, while other portions of the reservoir and/or theformed fractures may not be infiltrated, or may be infiltrated to alesser degree, by the hydraulic fracturing fluid composition (or arefilled with an amount of the hydraulic fracturing fluid composition thatis less than other portions of the fracture network). Because the fluidcomposition comprises an electrically conductive material, aconductivity contrast may exist between portions of the fracture networkdepending on the amount of the hydraulic fracturing composition that iscontained within that portion of the fracture network. Advantageously,this contrast may be used to map the fracture network, for example, byapplying electromagnetic radiation (EMR) from the surface to thesubterranean fracture network, wherein at least some portions of thefracture network are permeated by the hydraulic fracturing compositioncomprising the conductive proppant. These electromagnetic measurementscan be made from the surface and/or from nearby wellbores. While thisinformation may be used in other processes, in some embodiments, thisinformation may be used in guiding where and/or how electrohydraulicfracturing using the conductive hydraulic fracturing fluid is applied toa reservoir. Details regarding mapping a fracture network based on aconductivity contrast are also described below.

As mentioned above, in some embodiments, a hydraulic fracturingcomposition is described comprising one or more electrically conductivematerials. In some embodiments, this may include the use of conductiveproppants within the hydraulic fracturing fluid. The conductivity of theproppant may increase the conductivity of the hydraulic fracturingcomposition (e.g., a fluid, a slurry, a suspension). A variety ofproppants are suitable, so long as the proppants comprise of anelectrically conductive material. Non-limiting examples of conductiveproppant include ceramic particles (e.g., electrically conductiveceramic particles), coated particles (e.g., particles coated with aconductive material such as a conductive metal or other conductivematerial, conductive composite particles where the composite particlesinclude a non-conductive and conductive material), copolymers and resin,carbon particles (e.g., carbon black, acetylene black, petroleum coke,graphite, Carbolite), and metal particles (e.g., stainless steel shot).Additional non-limiting examples of conductive proppants include porousor sintered metals, such as aluminum or aluminum alloys. Combinations ofthese proppants are also possible (e.g., petroleum coke and anotherproppant).

In some embodiments, the hydraulic fracturing compositions may comprisea conductive proppant and a non-conductive proppant. For example, insome embodiments, the composition comprises a conductive proppant, suchas petroleum coke, and a non-conductive proppant, such as sand.Advantageously, mixing different types of conductive proppants withnon-conductive proppants may adjust properties of the other proppantand/or of the hydraulic fracturing composition, such as by increasingfracture permeability and/or hydraulic conductivity to a desired level.In some such embodiments, at least 10 wt %, at least 20 wt %, at least40 wt %, at least 50 wt %, or at least 60 wt % of the total proppant isnon-conductive proppant relative to the total amount of all proppantspresent in the hydraulic fracturing composition. By way of illustrationand not limitation, if the total amount of all proppants (e.g.,conductive proppant and non-conductive proppant) is 100 kg, then 50 kg(i.e. 50 wt %) of the proppant may be sand and the balance (i.e., 50 kg)may be conductive proppant, such as petroleum coke. Of course, thoseskilled in the art, in light of the present disclosure, will be capableof determining other appropriate amounts of non-conductive proppant andconductive proppant based on, at least in part, the desired conductivityof the composition and/or the fracture. Of course, however, it should beunderstood that for some other embodiments, the composition comprisesonly conductive proppant.

For some embodiments, the conductive proppant comprises an electricallyconductive portion and an electrically non-conductive portion. Forexample, the conductive proppant can be a core-shell material in whichthe exterior shell comprises an electrically conductive material (e.g.,a metallic coating) and the interior core comprises an electricallynon-conductive material (e.g., silica). In some embodiments, theelectrically conductive portion and the electrically non-conductiveportion are in a mixed arrangement, wherein portions of the electricallyconductive portion are intermingled with one another. For example,particles of a conductive proppant may be mixed with separate particlesof a non-conductive proppant. Other configurations of the electricallyconductive portion and the electrically non-conductive portion arepossible. Of course, in other embodiments, the conductive proppantcomprises only an electrically conductive portion, such that theentirety of the conductive proppant comprises an electrically conductivematerial.

In embodiments in which a conductive hydraulic fracturing fluid includesa proppant including a portion that is non-conductive, the electricallynon-conductive proppant material may correspond to any appropriatenon-conductive proppant material compatible with the processes describedherein. Non-limiting examples of electrically non-conductive materialsinclude alumina (Al₂O₃), silica (SiO₂), and/or polymers, such ascopolymers (e.g., resin C₂₁H₂₅ClO₅). In some embodiments, theelectrically non-conductive material is coated or mixed with anelectrically conductive material (e.g., a metallic coating, a conductivecarbon material) as noted above.

In some embodiments, the conductive proppant comprises an electricallyconductive material. In some embodiments, the conductivity of theelectrically conductive material is greater than or equal to 1×10² S/m,greater than or equal to 5×10² S/m, greater than or equal to 1×10³ S/m,greater than or equal to 5×10³ S/m, greater than or equal to 1×10⁴ S/m,greater than or equal to 1×10⁵ S/m, greater than or equal to 1×10⁶ S/m,or greater than or equal to 1×10⁷ S/m. In some embodiments, theconductivity of the electrically conductive material is less than orequal to 1×10⁷ S/m, less than or equal to 1×10⁶ S/m, less than or equalto 1×10⁵ S/m, less than or equal to 1×10⁴ S/m, less than or equal to5×10³ S/m, less than or equal to 1×10³ S/m, less than or equal to 5×10²S/m, or less than or equal to 1×10² S/m. Combinations of the foregoingranges are also contemplated (e.g., greater than or equal to 1×10² S/mand less than or equal to 1×10⁷ S/m). Other ranges are possible as thisdisclosure is not so limited.

In some embodiments, the hydraulic fracturing composition providesconductivity to a hydraulic fracturing fluid comprising the composition.In some embodiments, the conductivity of the hydraulic fracturing fluidis greater than or equal to 100 S/m, greater than or equal 150 S/m,greater than or equal 200 S/m, greater than or equal 250 S/m, greaterthan or equal 300 S/m, greater than or equal 500 S/m, greater than orequal 750 S/m, greater than or equal 1,000 S/m, greater than or equal1,250 S/m, greater than or equal 1,500 S/m, greater than or equal 1,750S/m, greater than or equal 2,000 S/m, greater than or equal 2,500 S/m,greater than or equal 3,000 S/m, greater than or equal 3,500 S/m,greater than or equal 4,000 S/m, greater than or equal 4,5000 S/m, orgreater than or equal 5,000 S/m, greater than or equal. In someembodiments, the conductivity of the hydraulic fracturing fluid is lessthan or equal to 5,000 S/m, less than or equal to 4,500 S/m, less thanor equal to 4,000 S/m, less than or equal to 3,500 S/m, less than orequal to 3,000 S/m, less than or equal to 2,500 S/m, less than or equalto 2,000 S/m, less than or equal to 1,750 S/m, less than or equal to1,500 S/m, less than or equal to 1,250 S/m, less than or equal to 1,000S/m, less than or equal to 750 S/m, less than or equal to 500 S/m, lessthan or equal to 300 S/m, less than or equal to 250 S/m, less than orequal to 200 S/m, less than or equal to 150 S/m, or less than or equalto 100 S/m. Combinations of the foregoing ranges are also possible(e.g., greater than or equal to 2,000 S/m and less than or equal to5,000 S/m). Other ranges are possible as this disclosure is not solimited.

The conductive proppant particles suspended within a hydraulicfracturing fluid may have a particular size or dimension. In some cases,the particles may preferably be spheres with relatively uniformdiameters. However, depending on the embodiment, different shapes and/ordistribution of sizes may also be used. In some embodiments, an averagemaximum transverse dimension of the conductive proppant is greater thanor equal to 1 μm, greater than or equal to 2 μm, greater than or equalto 3 μm, greater than or equal to 4 μm, greater than or equal to 5 μm,greater than or equal to 7 μm, greater than or equal to 10 μm, greaterthan or equal to 15 μm, greater than or equal to 20 μm, greater than orequal to 25 μm, greater than or equal to 30 μm, greater than or equal to40 μm, greater than or equal to 50 μm, greater than or equal to 100 μm,greater than or equal to 200 μm, greater than or equal to 300 μm,greater than or equal to 400 μm, greater than or equal to 500 μm,greater than or equal to 600 μm, greater than or equal to 700 μm,greater than or equal to 800 μm, greater than or equal to 900 μm, orgreater than or equal to 1,000 μm. In some embodiments, an averagemaximum transverse dimension of the conductive proppant is less than orequal to 1,000 μm, less than or equal to 900 μm, less than or equal to800 μm, less than or equal to 700 μm, less than or equal to 600 μm, lessthan or equal to 500 μm, less than or equal to 400 μm, less than orequal to 300 μm, less than or equal to 200 μm, less than or equal to 100μm, less than or equal to 50 μm, less than or equal to 40 μm, less thanor equal to 30 μm, less than or equal to 25 μm, less than or equal to 20μm, less than or equal to 15 μm, less than or equal to 10 μm, less thanor equal to 7 μm, less than or equal to 5 μm, less than or equal to 4μm, less than or equal to 3 μm, less than or equal to 2 μm, or less thanor equal to 1 μm. Combinations of the foregoing ranges are also possible(e.g., greater than or equal to 1 μm and less than or equal to 1,000μm). Other ranges are possible.

For some embodiments, the conductive proppant within a hydraulicfracturing fluid as described herein may have a particular porosity(i.e., the conductive proppant is a porous conductive proppant). In someembodiments, the conductive proppant has a porosity of greater than orequal to 10%, greater than or equal to 15%, greater than or equal to20%, greater than or equal to 25%, greater than or equal to 30%, greaterthan or equal to 40%, greater than or equal to 50%, greater than orequal to 60%, or greater than or equal to 70%. In some embodiments, theconductive proppant has a porosity of less than or equal to 70%, lessthan or equal to 60%, less than or equal to 50%, less than or equal to40%, less than or equal to 30%, less than or equal to 25%, less than orequal to 20%, less than or equal to 15%, or less than or equal to 10%.Combinations of the foregoing ranges are also possible (e.g., greaterthan or equal to 10% and less than or equal to 70%). Other ranges arepossible.

In some embodiments, the conductive proppant within a hydraulicfracturing fluid as described herein has a particular average pore size.In some embodiments, the conductive proppant has an average porediameter of greater than or equal to 50 nm, greater than or equal to 100nm, greater than or equal to 200 nm, greater than or equal to 250 nm,greater than or equal to 500 nm, greater than or equal to 750, greaterthan or equal to 1 μm, greater than or equal to 5 μm, greater than orequal to 10 μm, greater than or equal to 20 μm, greater than or equal to25 μm, greater than or equal to 50 μm, greater than or equal to 100 μm,greater than or equal to 250 μm, greater than or equal to 500 μm,greater than or equal to 750 μm, or greater than or equal to 1,000 μm.Combinations of the foregoing ranges are also possible (e.g., greaterthan or equal to 50 nm and less than or equal to 1,000 μm). Other rangesare possible as this disclosure is not so limited.

In some embodiments, the conductive proppant within a hydraulicfracturing fluid as described herein can withstand hydraulic fracturingpressures without significant damage to the conductive proppant (e.g.,cracking, breaking, shattering, a loss of electrical conductivity). Insome embodiments, the conductive particles are rated to withstandgreater than or equal to 30 MPa, greater than or equal to 50 MPa,greater than or equal to 75 MPa, greater than or equal to 100 MPa,greater than or equal to 125 MPa, or greater than or equal to 150 MPa.In some embodiments, the conductive particles are rated to withstandless than or equal to 150 MPa, less than or equal to 125 MPa, less thanor equal to 100 MPa, less than or equal to 75 MPa, less than or equal to50 MPa, or less than or equal to 30 MPa. Combinations of the foregoingranges are also possible (e.g., greater than or equal to 30 MPa and lessthan or equal to 150 MPa). Of course, other ranges are possible as thisdisclosure is not so limited. A suitable test for determining thepressure a conductive proppant can withstand is ISO 13503-2.

In some embodiments, the conductive proppant has a particular tensilestrength. In some embodiments, the tensile strength of the conductiveproppant is greater than or equal to 10,000 psi, greater than or equalto 20,000 psi, greater than or equal to 50,000 psi, greater than orequal to 90,000 psi, or greater than or equal to 100,000 psi. In someembodiments, the tensile strength of the conductive proppant is lessthan or equal to 100,000 psi, less than or equal to 90,000 psi, lessthan or equal to 50,000 psi, less than or equal to 20,000 psi, or lessthan or equal to 10,000 psi. Combinations of the above-referenced rangesare also possible (e.g., greater than or equal to 10,000 psi or lessthan or equal to 100,000 psi). Other ranges are possible.

In some embodiments, a hydraulic fracturing composition comprises atransport fluid. In some embodiments, a conductive proppant is dispersedand/or suspended in the transport fluid. The transport fluid maydissolve or suspend one or more conductive proppants and may deliver theconductive proppant to a reservoir or fractures within or proximate tothe reservoir or within the fracture network formed by the fracturingcomposition. A variety of fluids may be used as a transport' fluid.Non-limiting examples of a transport fluid include water (e.g.,freshwater, brine), compressed gas (e.g., liquefied petroleum gas), orcarbon dioxide (e.g., supercritical carbon dioxide). In someembodiments, the transport fluid comprises a polymer and/or aviscoelastic surfactant. In some embodiments, the transport fluidcomprises a borate, zirconium, and/or aluminum compound, which maypromote crosslinking within the transport fluid, which can increase theviscosity of the transport fluid. In some embodiments, the transportfluid comprises a hydrocarbon (e.g., an oil, diesel, liquifiedpetroleum) and/or an acid.

In some embodiments, the conductive proppant is present within thetransport fluid (e.g., suspended). In some embodiments, a weightpercentage of conductive proppant within transport fluid is greater thanor equal to 1%, greater than or equal to 2%, greater than or equal to3%, greater than or equal to 5%, greater than or equal to 10%, greaterthan or equal to 15%, greater than or equal to 20%, greater than orequal to 25%, greater than or equal to 30%, greater than or equal to40%, greater than or equal to 50%, or greater than or equal to 60%. Insome embodiments, a weight percentage of the conductive proppant withinthe transport fluid is less than or equal to 60%, less than or equal to50%, less than or equal to 40%, less than or equal to 30%, less than orequal to 25%, less than or equal to 20%, less than or equal to 15%, lessthan or equal to 10%, less than or equal to 5%, less than or equal to3%, less than or equal to 2%, or less than or equal to 1%. Combinationsof the foregoing ranges also possible (e.g., greater than or equal to 1%and less than or equal to 60%). Of course, other ranges are possible asthis disclosure is not so limited.

In some embodiments, the hydraulic fracturing compositions describedherein comprise a thickening agent. The thickening agent can alter theviscosity of the transport fluid (e.g., increasing its viscosity) asdesired for a particular reservoir. In some embodiments, the thickeningagent comprises a salt, such as potassium chloride (KCl). In someembodiments, the thickening agent comprises a polymer. Non-limitingexamples of suitable polymers include gum ghatti and/or guar gum.

The transport fluid is suitable for conveying conductive proppant underconditions for subterranean fracturing, which may have relatively hightemperatures and pressures. For example, the transport fluid may beconfigured such that is does not undergo a phase change within a rangeof temperatures and/or pressures, and hence may be heated and/or cooled.In some embodiments, the transport fluid is heated to a particulartemperature during use. The transport fluid may be selected such that itdoes not change phases (e.g., from liquid to a gas) during use in someembodiments. In some embodiments, the temperature of the transport fluidis greater than or equal to 40° C., greater than or equal to 50° C.,greater than or equal to 100° C., greater than or equal to 200° C.,greater than or equal to 250° C., greater than or equal to 500° C.,greater than or equal to 750° C., greater than or equal to 900° C., orgreater than or equal to 1,000° C. In some embodiments, the temperatureis heated to a temperature of less than or equal to 1,000° C., less thanor equal to 900° C., less than or equal to 750° C., less than or equalto 500° C., less than or equal to 250° C., less than or equal to 200°C., less than or equal to 100° C., less than or equal to 50° C., or lessthan or equal to 40° C. Combinations of the above-referenced ranges arealso possible (e.g., greater than or equal to 40° C. and less than orequal to 1000° C.). Other ranges are possible.

In some embodiments, an electric pulse can be administered via a pulsedpower device (e.g., an AC current). In some embodiments, the electricpulse has a voltage of greater than or equal to 1 V, greater than orequal to 5 V, greater than or equal to 10 V, greater than or equal to 50V, greater than or equal to 100 V, greater than or equal to 500 V,greater than or equal to 1 kV, greater than or equal to 5 kV, greaterthan or equal to 10 kV, greater than or equal to 50 kV, or greater thanor equal to 100 kV. In some embodiments, the electric pulse has avoltage of less than or equal to 100 kV, less than or equal to 50 kV,less than or equal to 10 kV, less than or equal to 5 kV, less than orequal to 1 kV, less than or equal to 500 V, less than or equal to 100 V,less than or equal to 50 V, less than or equal to 10 V, less than orequal to 5 V, or less than or equal to 1 V. Combinations of theforegoing ranges are also possible (e.g., greater than or equal to 1 Vand less than or equal to 100 kV). In another embodiment, the voltagemay be between or equal to 1 kV and 100 kV. Other ranges are possible asthis disclosure is not so limited.

In some embodiments, a pulse power device administers an electric pulsewith a particular amount of power. In some embodiments, the electricpulse has a power of greater than or equal to 1 MW, greater than orequal to 5 MW, greater than or equal to 10 MW, greater than or equal to50 MW, greater than or equal to 100 MW, greater than or equal to 500 MW,or greater than or equal to 1,000 MW. In some embodiments, the electricpulse has a power of less than or equal to 1,000 MW, less than or equalto 500 MW, less than or equal to 100 MW, less than or equal to 50 MW,less than or equal to 10 MW, less than or equal to 5 MW, or less than orequal to 1 MW. Combinations of the above-referenced ranges are alsopossible (e.g., greater than or equal to 1 MW and less than or equal to1,000 MW). Of course, other ranges are possible as this disclosure isnot so limited.

In some embodiments, an electric current can be administered via a DCpower device. In some embodiments, the electric current has a voltage ofgreater than or equal to 1 V, greater than or equal to 5 V, greater thanor equal to 10 V, greater than or equal to 50 V, greater than or equalto 100 V, greater than or equal to 500 V, greater than or equal to 1 kV,greater than or equal to 5 kV, greater than or equal to 10 kV, greaterthan or equal to 50 kV, or greater than or equal to 100 kV. In someembodiments, the electric current has a voltage of less than or equal to100 kV, less than or equal to 50 kV, less than or equal to 10 kV, lessthan or equal to 5 kV, less than or equal to 1 kV, less than or equal to500 V, less than or equal to 100 V, less than or equal to 50 V, lessthan or equal to 10 V, less than or equal to 5 V, or less than or equalto 1 V. Combinations of the foregoing ranges are also possible (e.g.,greater than or equal to 1 V and less than or equal to 100 kV). Inanother embodiment, the voltage may be between or equal to 1 kV and 100kV. Other ranges are possible as this disclosure is not so limited.

In some embodiments, a DC power device administers an electric currentwith a particular amount of power. In some embodiments, the electriccurrent has a power of greater than or equal to 1 MW, greater than orequal to 5 MW, greater than or equal to 10 MW, greater than or equal to50 MW, greater than or equal to 100 MW, greater than or equal to 500 MW,or greater than or equal to 1,000 MW. In some embodiments, the electriccurrent has a power of less than or equal to 1,000 MW, less than orequal to 500 MW, less than or equal to 100 MW, less than or equal to 50MW, less than or equal to 10 MW, less than or equal to 5 MW, or lessthan or equal to 1 MW. Combinations of the above-referenced ranges arealso possible (e.g., greater than or equal to 1 MW and less than orequal to 1,000 MW). Of course, other ranges are possible as thisdisclosure is not so limited.

Some embodiments are related to a system for providing a hydraulicfracturing composition to a subterranean reservoir. In some suchembodiments, the system comprises a pump configured to inject thehydraulic fracturing composition into the reservoir, wherein thehydraulic fracturing composition comprises a transport fluid and aconductive proppant. The system may also include, two or more electrodespositioned in two or more spaced apart bore holes configured to apply apotential across at least a portion of the reservoir and/or a proppanttank containing the hydraulic fracturing composition, where the proppanttank is in fluidic communication with the hydraulic fracturing pump.

The two or more electrodes may each be any suitable electrode forapplying a potential across the reservoir. In some embodiments, the twoor more electrodes are configured to apply a voltage potential between afirst portion of the reservoir and a second portion of the reservoir. Insome such embodiments, the applied voltage potential heats the reservoir(e.g., via Joule heating) due to the flow of current between the two ormore electrodes located in at least the first and second portions of thereservoir. Non-limiting examples of appropriate electrodes may includetitanium, aluminum, copper, and alloys and/or compounds thereof. In oneembodiment, an electrode may comprise cobalt beryllium copper.

In some embodiments, a fracture network associated with one or morereservoirs can be mapped or imaged. As described above and elsewhereherein, the conductive hydraulic fracturing fluids disclosed herein maypenetrate portions of a reservoir and any fractures associated with thereservoir. In some embodiments, as the hydraulic fracturing composition,comprising a conductive material, is pumped into a reservoir, it maycreate new fractures and/or cause existing fractures to propagate. Insome such embodiments, the conductive material may infiltrate at leastsome portions of the fractures while not penetrating at least some otherportions of the fracture. The difference in the amount of the conductivematerial (or the hydraulic fracturing composition comprising theconductive material) that penetrates different portions of the reservoirand/or associated fracture network may allow for the characterization ofthe fracture network. Advantageously, the fracture network may becharacterized from a position above a subterranean reservoir, forexample, from a position on the surface of a drill site. In someembodiments, electromagnetic radiation is applied to the reservoir, andone or more resulting signals related to the applied electromagneticradiation may be received from the reservoir. These signals may be usedto determine one or more properties of the reservoir and/or theassociated fracture network can be determined based, at least in part,on the one or more signals.

In some embodiments, the two or more electrodes may apply a voltage tothe reservoir or otherwise provide current to the reservoir (e.g.,fracturing fluid within the reservoir). In some such embodiments, apulsed power system may be used. The pulsed power system is based on theprinciple of parallel charge and parallel discharge of very lowinductance strip line capacitors through suitable spark gap systemswhich can handle peak currents and electrical stresses. It can have atleast 110 V, at least 208 V, at least 230 V, at least 480 V, or highervoltage alternating current as input power. In some embodiments, it mayfurther comprise a filter and/or a DC rectifier to convert AC to DC, aswell as current controls and/or chargers to store energy in energystorage devices such as capacitor banks.

In some embodiments, a DC current is applied across the two or moreelectrodes. In some such embodiments, the DC current is applied after apulse AC current. Advantageously, applying a DC current may furtherfracture the reservoir relative to applying only an AC current.

As used herein, a well may refer to a borehole extending into ageological feature. For example, a borehole may extend through one ormore strata disposed between an upper ground surface of a formation anda reservoir that the bore hole is used to access. This may includeapplications such as, petroleum producing reservoirs (e.g., oil and gasproducing reservoirs); water reservoirs; geothermal reservoirs includingEnhanced Geothermal Systems (EGS), carbon sequestration reservoir,in-situ mineral mining reservoir; and/or any other appropriategeological feature that a borehole may be formed in.

Turning to the figures, specific non-limiting embodiments are describedin further detail. It should be understood that the various systems,components, features, and methods described relative to theseembodiments may be used either individually and/or in any desiredcombination as the disclosure is not limited to only the specificembodiments described herein.

FIG. 1A shows a schematic illustration of a generalized arrangement 100for stimulating a reservoir with an electrically conductive hydraulicfracturing composition (e.g., using a hydraulic fracturing fluidcomprising one or more conductive materials). In the figure, asubsurface reservoir 110 is positioned between each of drilled wells 120and 130 (e.g., two or more spaced apart wells). The system may beconfigured to perform an electrohydraulic fracturing process such as alow-frequency electrical treatment, a pulsed-power treatment, and/oranother appropriate electrohydraulic fracturing process where a voltagepotential is applied to the reservoir formation between the two or morewells as described in more detail below and elsewhere herein. Thedepicted wells may be petroleum-producing units (e.g. gas and/or oil)that tap a reservoir that may contain petroleum mixed with ground water(e.g., fresh water, bine). Of course, this process may be applied toother appropriate wells too (e.g., geothermal wells associated withthermoelectric production, wells associated with carbon sequestration,wells associated with mineral recovery and mining, and/or any otherappropriate application). Wells 120 and 130 include a respective headassembly 122 and 132 that can be arranged to include a pump 134 alongwith various valves and connections, such as particular structuresresiding within casings 126 and 136 that facilitate petroleum productionor any other desired process associated with the wells as describedherein. At the depth of the reservoir 110, each of casings 126 and 136may include perforations extending from an interior of the well to thewell exterior through the casings, as shown in the figure, to allowfluid communication between the well interior and the reservoir throughthe casings. The casings and perforations may be configured such thatthe conductive hydraulic fracturing fluids disclosed herein may flowthrough the one or more perforated casings located at a desired positionwithin a reservoir.

The permeability of the reservoir is a function of the rate and degreeof petroleum production, or, in the case of a geothermal well, therecharge rate of circulated geo-fluid (e.g., water, brine,petroleum-water/brine mixtures, etc.). While not shown in the figure, aconductive hydraulic fracturing fluid as described herein can beinjected via each of respective well heads 122 and 132 to assist ingenerating increased permeability in the reservoir. As shown in FIG. 1A,after pumping a conductive hydraulic fracturing fluid into the reservoir110, the system can employ electricity provided from a power source 144,such as the power distribution source shown in the figure, a local powergenerator, one or more batteries, and/or any other appropriate powersource, to increase permeability in the space of the reservoir 110between wells 120 and 130. The electric connection may be made via eachrespective well head assembly 122 and 132 using appropriate wires andconduits that extend within the well and/or energize the casing. In someembodiments, the electrodes 140 that may be electrically connected tothe power source and used to energize the reservoir may be localized tothe depth containing the reservoir and the leading portion of theconductor may be an insulated cable. This may be done by electricallyinsulating the distal energized casings from a proximal portion of thecasings lining the wells. By localizing the location where a voltage andcorresponding current is applied to a reservoir at a sufficient depth,the risk of current flowing to the surface in any significant quantitymay be mitigated. Hence, as shown in the figure, the localized current(arrows 142) flows between the wells 120 and 130 within the reservoir110. Without wishing to be bound by theory, the current flowing betweenthe electrodes may cause physical changes to occur within the matrix ofsand, clay, rock, and other compounds, in a manner that increasespermeability. For example, in some embodiments, the current flowingbetween the wells may result in Joule heating of the reservoir where thecurrent causes heat to be generated in the reservoir causing the localtemperature of the reservoir in portions of the reservoir where thecurrent is passed to increase. This rapid heating may cause increasedfracturing within the reservoir. Additionally, after heating, a coolfluid with a temperature less than the heated reservoir, such as liquidwater, brine, or other appropriate fluid, may be introduced to thereservoir to induce thermal shock due to rapid cooling within thereservoir which may induce further fracturing of the reservoir in someembodiments.

As described in more detail elsewhere herein, one or more appropriatecontrollers 150 may be operatively connected to the one or more powersource(s) 144, well heads 134, and/or any other appropriate component ofthe electrohydraulic fracturing systems disclosed herein. In someembodiments, the one or more controllers may include a pulsed powersystem 158, low-frequency electrical treatment system, or otherappropriate system configured to apply a desired type of electricalstimulation to a reservoir. In some embodiments, the one or morecontrollers may include or be associated with a DC power source 159,which may provide Joule heating to the conductive proppant and/or thereservoir. The controller may include one or more processors 152 andassociated memory that includes processor executable instructions thatwhen executed by the one or more processors cause the various componentsof the system to perform any of the processes disclosed herein. The oneor more processors 152 can also interconnect with various sensorsincluding one or more of any of current and voltage probes, temperaturesensors, pressure sensors, electromagnetic resonance (EMR) sensors, flowsensors, and/or any other appropriate sensor. This connection may eitherbe a direct connection and/or one or more sensor processors 154 may beconnected to the one or more processors 152. Depending on the specificsensor, the different sensors may be located within the well(s) or inline with the power system to measure flow of current between wells,voltage potential applied between the wells, and/or other parameters,such as flow rate of the fluid and/or an EMR signal received afteremitting an EMR signal from a signal generator. These and otherprocesses 156 can be instantiated within a standalone processingarrangement—such as an FPGA, and/or can be connected via interfaces witha general purpose computing environment 160. Such can include a PC,server, laptop, tablet, smartphone, or other computing device having aninterface, for example, a display/touchscreen 162, keyboard 164 and/ormouse 166. Appropriate wired and/or wireless networking links can alsobe provided as appropriate, and in accordance with those of ordinaryskill in the art.

FIG. 1B is an overview of a system 500 for hydraulic fracturing,electrical stimulation, and hydro-electric fracturing. In someembodiments, a first well is drilled into an enhanced geothermal system(EGS) reservoir R, e.g., hard dry rock. The first well 506 (alsoreferred to as wellbore) can be any type of well, such as a productionwell, an injection well, such as a vertical or horizontal injectionwell, or the like. In this example, the first well 502 is drilledthrough one or more sedimentary layers into a target reservoir area R.The target reservoir area R may have little or no in-situ brine as canbe found in hot dry rocks in enhanced geothermal systems and/or a lowwater saturation, such as below 20% water saturation as can be found inhydrocarbon saturated tight/low permeability clastic reservoirs. In suchconditions, electrical stimulation may be ineffective, and the presentcombined techniques of hydraulic fracturing and electrical stimulationmay increase permeability. Natural hydraulic fractures may exist in thetarget reservoir area R and may be injected with a combination of afluid (e.g., electrically conductive fluid, such as a brine) and/orelectrically conductive proppant 522 (e.g., injected fluid/proppantmixture), may introduced at a high pressure by hydraulic fracturing pump518, and hydraulic fracturing operations are conducted in order tostimulate the re-opening of existing natural fractures 520 and theinitiation and propagation of new hydraulic fractures (also referred toas artificial fractures) away from the first well. The proppant may beany appropriate proppant as disclosed herein. Also, the fluid may be anelectrically conductive fluid, such as brine.

The extent and magnitude of existing natural fractures 520 and newhydraulic fractures may be monitored and mapped by one or more receivers510. The receivers 510 can be any combination of magnetotelluric,micro-seismic, and/or electromagnetic imaging receivers capable ofmonitoring, imaging, and mapping existing natural fractures and newhydraulic fractures (collectively referred to as “fracture network”) inthe target reservoir area R. The receivers can monitor, image, and mapthe fracture network concurrently with the hydraulic fracturing, afterhydraulic fracturing is complete, or some combination thereof. Thenumber, amount, type of receivers, and measurements taken can varyaccording to various aspects of the disclosure and according to thegeography of a site and the particular system. Additionally oralternatively, monitoring, imaging, and mapping can be conducted withinthe first well by logging, such as density/neutron, and/or boreholeimaging methods, such as acoustic imaging, after hydraulic fracturing.Mapping of the fracture network can also show which areas of the firstwell and target reservoir area R with limited hydraulic fracturinginitiation and development can benefit from additional targetedstimulation. In this example, the new fractures near the toe of the wellare assumed to be minor in comparison to the existing natural fracturesthus making additional electrical stimulation in this area advantageous.In addition to the example shown, this method can also be applied to:fields with existing wells or to fields where additional wells are notplanned, in that subsequent electrical stimulation steps are conductedbetween at least two wells.

Time-lapse resistivity imaging, such as magnetotellurics, may be coupledwith micro-seismic events to better characterize and image the fracturenetwork in some embodiments. Resistivity imaging methods can detect thecontrast between highly conductive fluid filled fractures and the highlyresistive reservoir formation and provide additional information onfracture connectivity and aperture in some embodiments.

In some embodiments, at least one second well 508 may be drilled. The atleast one second well (also referred to as wellbore) can be any type ofwell, such as a production well, an injection well, such as a verticalor horizontal injection well, or the like. The at least one second wellcan also include a plurality of wells, according to one or moreembodiments.

The at least one second well may be targeted and drilled such that itintersects the fracture network created by hydraulic fracturingconducted. In some examples, several wells can be drilled and targetdepending on the fracture network generated. One or more electrodes 524a, b of opposite charges are lowered into the first well and secondwell. This may Be accomplished using high voltage cables 526 having theelectrode at one end and being interconnected to one or both of thepulsed power device 502 and/or DC power supply 504 positioned at thesurface. In one example, the electrode 524 a can be an anode andelectrode 524 b can be a cathode, the respective polarities can bereversed according to various embodiments. The electrodes 524 a and 524b can be moved to one or more additional electrode positions within thewells by feeding or withdrawing length of high voltage cables 526accordingly. In other examples, a plurality of electrodes 524 a, b canbe lowered into each of the respective wells and to achieve simultaneouspositioning of the several electrode positions.

The electrodes can be attached to a bottom-hole-assembly stimulationtool 530, where the cable is connected to the electrode inside the tool530 using a connector. The tool 530 enclosure can isolate the electrodefrom the high pressure and electrically conductive environment of theborehole. The tool 530 can move inside the wellbore to differentstimulation zones and electrode positions using mechanisms such as welltractors. Nonconductive insulating packers can be set above and below orleft and right sides of the electrode to isolate the operation zoneelectrically and hydraulically from the rest of the borehole.

In some embodiments, the pulsed power device 502 (powered by, forexample, electricity line 510, which can receive power from the grid ora generator) rapidly release a predetermined electrical pulse, orelectric shock, of electrical energy. The predetermined pulse, orelectric shock, can be delivered for a predetermined amount of time, orcan be delivered until the electrical impedance between the electrodes524 a, breaches a minimum, indicating peak electrical fracturing hasbeen achieved. The predetermined pulse can be delivered at up to 1,000Megawatts to deliver up to 120 kJ of energy, though any appropriatepower and/or energy may be used depending on the embodiment.

The electrical pulses may cause uneven heating, sudden expansion ofminerals, and vaporization of pore fluid which can result in up to aneight order of magnitude increase in rock permeability under laboratoryconditions. Differential thermal expansion of the fluid compared to thereservoir rock may induce micro-fracture propagation due to tensilefailure, adding additional permeability to the target zone. Inparticular, the electrical pulse can increase permeability in fracturestoward the toe of each well, which will counter the pressure drop in thetarget reservoir area R, and thus prevent short circuiting. The DC powerdevice 504 with a voltage up to 100 kV and a power up to 1000 MW, orother appropriate power parameter, (powered by, for example, electricityline 510, which can receive power from the grid or a generator) may beused to joule heat the mixture of conductive fluid and proppant in thefracture network. Electrical stimulation may advantageously reducebreakdown pressure needed for hydraulic fracturing by 5-50% and Jouleheating of the reservoir area (2-8× temperature increase or otherappropriate temperature increase) represented conceptually as heatingzone 528, to induce thermal expansion and micro-fracture propagation.Electrical stimulation also allows for targeted stimulation to enhancefracture development in areas identified as having limited hydraulicfracture propagation (represented by electrode pairs 524 a, b).

Temperature increase will be dependent on exemplary parameters such asthe reservoir properties as well as the voltage and power applied. Inthe example where coke is the proppant, the temperature can be heated to800 C as the coke can experience a reduction of electrical conductivityabove this temperature.

Cold water may be injected into the first well 306. Because the targetreservoir area R was heated, in some examples at 2× to 8× temperatureincrease, during electrical stimulation described above, the injectionof surface temperature, water which is significantly cooler thanreservoir temperature (in this the injected fluid may be 20 C at thesurface, but is highly variable depending on the particular embodiment),may result in quenching of the heated reservoir. Rapid thermal gradientand resulting stresses can cause the initiation and propagation ofmicro-fractures in the direction of fluid flow in the heated region 528.The hydraulic fracturing conducted can optionally be repeated one ormore times.

The high temperature differential between the superheated fracturesurface and the colder injection water may cause “thermal shock” of thereservoir, which can lower the reservoir breakdown pressure by up to400% and increase permeability by up to four times in some embodiments.Applying EHF increases the fracture number and volume within a givenregion of reservoir rock as compared to hydraulic fracturing alone.

Applying HEF (hydro-electric fracturing) may increase the fracturenumber and volume within a given region of reservoir rock than hydraulicfracturing alone. In the case of EGS, the injected water may be heatedto reservoir temperature as it is circulated through the fracturenetwork toward the producer well. The hot water may be pumped from thewell to geothermal power plant 512 via pipeline 514 and utilized forpower generation before being reinjected into well another wellhydraulically connected to the producer well via the induced fracturenetwork.

In FIGS. 2A-2C, non-limiting examples of hydraulic fracturingcompositions comprising a conductive proppant are schematicallyillustrated. In FIG. 2A, a hydraulic fracturing composition 200comprises a transport fluid 210 with a plurality of conductive proppants220 dispersed within the transport fluid 210, where the proppant maycomprise an electrically conductive material. In some embodiments, whileflowing the conductive material may be uniformly distributed within thetransport fluid. However, after being injected into a reservoir, theconductive material, e.g., a conductive proppant, may become compactedwithin the fractures such that the proppant particles are in contactwith one another. While uncoated conductive materials are shown in FIG.2A, other configurations are possible. In some such embodiments, theconductive proppant may have a core-shell arrangement. For example, inFIG. 2B, conductive proppant 220 includes a plurality of core shellparticles including a conductive coating 230 and a core 240 at leastpartially encapsulated by the conductive coating. In some embodiments, aplurality of core shell particles may include at least a portion wheremultiple cores are at least partially encapsulated in a single coatingsuch that the core shell particles include multiple cores within asingle particle. In some such embodiments, the core comprises anelectrically non-conductive material and the coating comprises anelectrically conductive material (e.g., a metallic coating). However,other arrangements are possible, and, in some cases, both the core andthe shell may comprise an electrically conductive material. And otherconfigurations other than core shell arrangements are possible, as thisdisclosure is not so limited.

For some embodiments, it may be advantageous to increase the thicknessor viscosity of the hydraulic fracturing. Accordingly, the electricallyconductive hydraulic fracturing compositions disclosed herein may alsocomprise a thickening agent, as mentioned elsewhere herein. FIG. 2Cschematically depicts a hydraulic fracturing composition 200 comprisinga plurality of conductive proppants 220 dispersed therein and alsoincluding thickening agents 250 dispersed in the fluid. Additionaldetails regarding the thickening agent are described elsewhere herein.

FIGS. 3A-3E schematically depict a method for electrohydraulicfracturing using electrically conductive hydraulic fracturing fluids. InFIG. 3A, the first well 302 is drilled through one or more rock layers303 into a target reservoir area 304. The target reservoir area 304 mayhave little or no in-situ brine as can be found in hot dry rocks inenhanced geothermal systems and/or a low water saturation, such as below20% water saturation as can be found in hydrocarbon saturated tight/lowpermeability clastic reservoirs. In such conditions, conventionalelectrical stimulation can be ineffective, and the present electricalsimulation described herein using conductive proppants can increasepermeability. Natural hydraulic fractures 306 in the target reservoirarea 304 may be injected with an electrically conductive hydraulicfracturing fluid 305 and hydraulic fracturing operations may beconducted in order to stimulate the re-opening of existing naturalfractures 306 and the initiation and propagation of new hydraulicfractures 308 (also referred to as artificial fractures) extending awayfrom the first well 302. FIG. 3B is another view of area 307 depictingthe new hydraulic fractures 308 filled with electrically conductiveproppant 304 from the conductive hydraulic fracturing fluid used to openthese new fractures.

The extent and magnitude of existing natural fractures 306 and newhydraulic fractures 308 formed by the fracturing fluid can be monitoredand/or mapped by one or more receivers 310. Without wishing to be boundby any particular theory, it is believed that a difference in theresistivity based on the amount of conductive proppant present allowsthe fracture to be mapped, as resistivity imaging methods can detect thecontrast between highly conductive fluid filled fractures and the highlyresistive reservoir formation and provide additional information onfracture connectivity and aperture. The receivers can be any combinationof magnetotelluric, micro-seismic, and/or electromagnetic imagingreceivers configured to monitor, image, and/or map existing naturalfractures 306 and new hydraulic fractures 308 (which may collectivelyrefer to the “fracture network”) in the target reservoir area 303. Asdescribed and elsewhere herein, inclusion of a conductive proppantwithin the fracturing fluid may increase the contrast between portionsof the fracture containing the fracturing fluid relative to portionswith less (or no) fracturing fluid. The receivers 310 can monitor,image, and/or map the fracture network concurrently with or separatelyfrom the hydraulic fracturing and/or after hydraulic fracturing. Thenumber, amount, type of receivers 310, and measurements taken can varyaccording to various aspects of the disclosure and according to thegeography of a site and the particular system employed to inject thehydraulic fracturing composition. Additionally or alternatively,monitoring, imaging, and mapping can be conducted within the first well302 by logging borehole characteristics using measure methods such asdensity/neutron based measurements and/or borehole imaging methods suchas acoustic imaging after hydraulic fracturing. Mapping of the fracturenetwork can also show which areas of the first well 302 and targetreservoir area 303 exhibit limited hydraulic fracturing initiation anddevelopment which might benefit from additional targeted stimulation.For example, the new fractures 308 near the toe 312 of the well 302 maybe smaller in comparison to the existing natural fractures 306 and/orother new induced fractures thus making additional electricalstimulation in this area advantageous. In addition, the method may alsobe applied to fields with existing wells or to fields where additionalwells are not yet planned, in order to determine where new wells can bedrilled.

In some embodiments, at least one second well can be drilled. In FIG.3C, second well 316 is shown. The second well, like the first well, canbe any type of well, such as a production well, an injection well, suchas a vertical,horizontal, or inclined injection well, or the like. Theat least one second well can also include a plurality of wells,according to one or more embodiments. In some embodiments, several wellscan be drilled and targeted depending on the fracture network generated.One or more electrodes, 324 a and 324 b, of opposite charges, can belowered into the first well 302 and second well 316. This may beaccomplished by using high voltage cables 326 having the electrode atone end and being interconnected to one or both of the pulsed powerdevice 302, a direct current (DC) power supply 304, or any otherappropriate power supply positioned at the surface. In some instances,the electrode 324 a is an anode and electrode 324 b can be a cathode,the respective polarities of which can be reversed, as desired.

FIG. 3C schematically depicts electrodes 324 a and 324 b and one or moreadditional electrode positions 324 a 2-324 a 4 and 324 b 2-324 b 4. Theelectrodes 324 a and 324 b can be moved to the additional electrodepositions within the wells 302 and 316, respectively, by feeding orwithdrawing a length of high voltage cables 326 accordingly. In somecases, a plurality of electrodes 324 a and 324 b can be lowered intoeach of the respective wells 302 and 316 to achieve simultaneouspositioning of the several electrode positions. The electrodes can beattached to a bottom-hole-assembly stimulation tool 330, where the cableis connected to the electrode inside the tool 330 using a connector. Thetool 330 enclosure can isolate the electrode from the high pressure andelectrically conductive environment of the borehole. The tool 330 canmove inside the wellbore to different stimulation zones and electrodepositions using mechanisms such as well tractors, a drill string theelectrodes are attached to, or any other appropriate method forpositioning the electrodes within the wells. Non-conductive insulatingpackers 360 a and 360 b can be set both upstream and downstream from theelectrode within the borehole (e.g., well) to isolate the operation zoneelectrically and hydraulically from the rest of the borehole.

In FIGS. 3C-3D, the pulsed power device 302, powered by electricity line310, which can receive power from the grid, a generator, a renewablesource such as solar, or other power sources, releases a predeterminedelectrical pulse of electrical energy. The predetermined pulse, orelectric shock, can be delivered for a predetermined amount of time, orcan be delivered until the electrical impedance between the electrodes324 a, breaches a minimum, indicating peak electrical fracturing hasbeen achieved. Without wishing to be bound by any particular theory, theelectrical pulses can cause uneven heating, sudden expansion of mineralsor geofluids, and/or vaporization of pore fluid which can result in anincrease in rock permeability (e.g., permeability may increase byseveral orders of magnitude relative to when electrical pulses are notused including, for example, an increase in permeability on the order of10⁸ relative to when electrical pulses are not used may be provided insome instances). Differential thermal expansion coefficient of the fluidcompared to the reservoir rock induces mechanical stresses andmicro-fracture propagation due to tensile failure, adding additionalpermeability to the target zone. In particular, the electrical pulse canincrease permeability in fractures toward the toe 312 of each well (302or 316), which will counter the pressure drop in the target reservoirarea 303, and thus prevent short circuiting.

FIG. 3C in particular depicts four discrete stimulation stages whereelectrode 324 a (e.g., anode) is placed at position 324 a and electrode324 b (e.g., cathode) is placed at position 324 b, the target reservoirarea 303 is electrically stimulated (stimulated zone representedgenerally by 320) for the predetermined time or until an impedance valueis reached, then the electrodes (anode and cathode) are moved tolocations 324 a 2 and 324 b 2 respectively and the stimulation isrepeated, then to 324 a 3 and 324 b 3, then 324 a 4 and 324 b 4. Thisorder may be reversed, and the number of stages is not limited to thoseshown in the figure. The DC power device 304, which can receive powerfrom the grid, a generator, or other power source, is used to Joule heatthe mixture of hydraulic fracturing fluid comprising conductive proppant308 in the fracture network, or the conductive channels. DC power device304 can be used to Joule heat the mixture of conductive proppant 308 andtransport fluid in the fracture network. Electrical stimulation canadvantageously reduce the breakdown pressure needed for hydraulicfracturing by 5-50% and Joule heating of the reservoir area to inducethermal expansion and micro-fracture propagation indicated by 324.Electrical stimulation also allows for targeted stimulation to enhancefracture development in areas identified as having limited hydraulicfracture propagation (represented by electrode pairs 324 a, 324 b, and324 a 2 and 324 b 2).

FIG. 3D in particular shows a schematic of an enhanced view of zone 320depicting micro-fracture initiation and propagation 324 away from thehydraulically induced fractures 308 and the electrical current 318traveling through the electrically conductive fluid 302 and conductiveproppant 304.

In FIG. 3E, cold water 305 is injected into the first well 302. Becausethe target reservoir area 303 was heated during electrical stimulation,the injection of a lower temperature liquid, such as surface-temperaturewater, which is significantly cooler than reservoir temperature, canresult in quenching of the heated reservoir 324. Rapid thermal gradientsand resulting stresses may be formed within the reservoir which cancause the initiation and propagation of micro-fractures 322 in thedirection of fluid flow in the heated region 326. FIG. 3F shows anotherview of zone 320 depicting fracture initiation and propagationprocesses. Due to the increased electrical conductivity in portions ofthe reservoir extending between two adjacent wells associated with theuse of electrically conductive hydraulic fluid, applying hydroelectricfracturing using conductive proppants may increase the fracture numberand volume within a given region of reservoir rock than hydraulicfracturing without use of a conductive proppant. In some cases, theinjected water is heated to reservoir temperature as it is circulatedthrough the fracture network toward the producer well 316. The hot water350 may be pumped from the well 316 to a geothermal power plant 312 viapipeline 314 and utilized for power generation before being reinjectedinto well 302.

FIG. 4 is a flow chart depicting a method 400 a of hydraulic fracturing.At block 405 a of the figure, a first well is drilled into a reservoir,e.g., within hard dry rock. At block 410 a, an electrically conductivehydraulic fracturing composition, which may comprise a conductivematerial, such as a conductive proppant, can be introduced to the firstwell. The electrically conductive fracturing fluid may be appropriatelypressurized and injected into the first well at pressures sufficient toinduce fracturing and/or to introduce the electrically conductivefracturing fluid into the fracture network within the first well. Atoptional block 415 a, the extent and magnitude of existing naturalfractures and any new hydraulic fractures may be characterized. This mayinclude performing any appropriate type of characterization of the wellsusing any appropriate type of one or more receivers. In someembodiments, time-lapse resistivity imaging, such as magnetotellurics,can be coupled with micro-seismic events to characterize and image thefracture network. In other embodiments, resistivity imaging methods canbe used to detect the contrast between highly conductive fluid filledfractures and the highly resistive reservoir formation and provideadditional information on fracture connectivity and aperture. This mayhelp to provide information related to the connectivity within thedifferent regions of a reservoir which may be used to guideelectrohydraulic fracturing processes. For example, if a particularfracture between two portions of a reservoir are large enough that thefracture would function as a short circuit path during electrohydraulicfracturing, an electrohydraulic fracturing process may be electricallyisolated from such a fracture. Similarly, if a portion of a reservoirextending between two or more bore holes shows insufficient connectivityfrom the electrically conductive hydraulic fracturing fluid, and thuswould exhibit a reduced effect from electrohydraulic fracturing, then anelectrohydraulic fracturing process may be performed elsewhere withinthe two or more wells. Thus, the noted characterization techniques maybe used to target electrohydraulic fracturing processes on one or moreportions of a reservoir that show sufficient connectivity to facilitateelectrohydraulic fracturing while not exhibiting too large aconnectivity such that electrohydraulic fracturing would be ineffectivein such a region.

At 420 a, at least one second well can be drilled. Based, at least inpart, upon the mapping conducted at block 415 a, the at least one secondwell can be targeted and drilled such that it intersects the fracturenetwork created by hydraulic fracturing conducted at block 410 a. Atblock 425 a, one or more electrodes of opposite charges are lowered intothe first well, the second well, and/or any number of other wells to betargeted during an electrohydraulic fracturing process.

At block 430 a, a voltage potential is applied across the electrodes anda current is passed through the reservoir and electrically conductivehydraulic fracturing fluid. A pulsed power device, or other appropriatepower source, may release a predetermined electrical pulse, ofelectrical energy. The predetermined pulse, can be delivered for apredetermined amount of time, or energy, or can be delivered until theelectrical impedance between the electrodes, is reduced to a minimumelectrical impedance, indicating peak electrical fracturing has beenachieved. During application of the voltage potential, at block 435 a,the current passing between the electrodes may result in Joule heatingof the mixture of transport fluid and conductive proppant 408 in thefracture network as well as the reservoir itself.

At optional block 440 a, a cooling fluid, such as a cold liquid (e.g.,water or brine), with a temperature less than the heated well can beinjected into the first and/or the at least one second well. Because thetarget reservoir area was heated, the cooling fluid from the surface maybe significantly cooler than reservoir temperature, which can cause theinitiation and propagation of additional fractures. After block 440 a,the electrohydraulic fracturing process described above can optionallybe repeated one or more times. The high temperature differential betweenthe superheated fracture surface and cold injection fluid causes“thermal shock” of the reservoir, which can lower the reservoirbreakdown pressure (e.g., by up to 400%) and increase permeability(e.g., by up to four times). As another advantage, the use of conductiveproppants may reduce or minimize short circuiting (i.e., fluid pathwaysbetween adjacent wells that reduce productivity) by utilizing theelectromagnetic properties of the electrically conductive proppant tobetter characterize fracture properties related to fluid flow. And theelectric energy parameters (e.g., voltage, current, duration), andinjection parameters (flow rate, time, pressure, temperature), or anycombination of these parameters can be adjusted and/or optimized tocontrol the created fracture's width, length, and/or number.

FIG. 7 shows a generalized arrangement 700 for proof of concept/model ofa system and method for increasing reservoir permeability via aLow-Frequency Electrical Treatment (LFET). The arrangement consists ofan AC current power source 710 and voltage source 712, which powers apreheating coil 714 (which could be a nichrome heating element, forexample) wrapped around a high-pressure-high-temperature (HPHT)cylindrical cell 720. The cell 720 contains a core sample 722, whichcorresponds to the reservoir rock/sedimentary material. The cell 720includes an inlet pressure gauge 730 and outlet pressure gauge 732, aswell as a flow meter 734 at the outlet thereof. Flow of fluid (arrows F)is controlled by a series of valves 740, 742 and 744. The fluid circuitincludes a fluid (water/brine) tank (acting as a fluid capacitor) 750and associated pump 760.

The arrangement 700 is adapted to simulate the (HPHT) regime close tothe reservoir conditions, and how the sample 722 will react to the LFETprocess applied thereto. High temperature is achieved by the preheater714, and the high-pressure condition is reached by screw bolt system770, 772 acting as a piston inside the cylindrical body of the cell. Thetwo pressure gauges 730, 732 read the pressure data at the inlet andoutlet stages. The flowmeter 734 provides feedback to control the flowrate at the pump 760. Several (e.g. K-type) thermocouples can be placedalong the core sample 722 to read the temperature. All data generated bythe sensors, pumps and other devices within the arrangement 700 can beinterconnected with a data-acquisition and handling computer (and/orprocessor) 780 running an appropriate software program 782, such asLabView®, available from National Instruments Corporation of Austin,Tex., which is used for collecting and post-processing of the data 784.The computer/processor 780 receives user control inputs 786 to adjustthe parameters of the arrangement via an appropriate user interface andthe computer/processor outputs status, performance and result data (e.g.textual, numerical, graphical, etc.) 788 via the user interface.

FIG. 8 is a schematic diagram of an exemplary lab scale experimentalarrangement for determining and maximizing the efficacy of the pulsedelectrical stimulation of core samples 822, and a generalizedarrangement 800 for proof of concept/model of a system and method forincreasing reservoir permeability via pulsed ERS. The setup consists ofHigh Voltage Pulsed Power System 830, a switch 834 and a controller 850to configure voltage and pulse settings, an oscilloscope 840 connectedto a voltage probe 836 and a current probe 838 to measure transientpulse voltage and current waveforms, and two electrodes 814, 816extended into the pressure testing chamber 810. The two electrodes 814and 816 can have an electrode distance ED between them of approximately1 to 6 inches. Inside the pressure testing chamber 810, there are twothermally and electrically insulated ceramic containers 812 filled withsaline brine or other geo-fluids 818. The two ceramic containers 812hold the rock core sample 822 (which corresponds to the reservoirrock/sedimentary material) in between them through machined holes. Thetwo ceramic containers 812 and the rock core sample 822 can have asealing system around them. The temperature of the rock sample 822 iscontrolled by a temperature controller and DC power source. The testingchamber 810 is connected to a compressed air line 820 and its valves 826to provide expected pressure. High pressure high temperature conditions(HPHT) increase accuracy of the experiment as it simulates reservoirconditions. The pressure chamber can have a temperature sensor 827 and apressure sensor 828, and safety pressure relief valve 829. Temperaturecontroller 842 powers a preheating coil 824 (e.g., a nichrome heatingelement) wrapped around core sample 822. The container 812 contains acore sample 822.

All data generated by the sensors, pumps and other devices within thesetup and test cell can be interconnected with a data-acquisition andhandling computer (and/or processor) 880 running an appropriate softwareprogram 882, such as LabView®, which is used for collecting andpost-processing of the data 884. The computer/processor 880 receivesuser control inputs 886 to adjust the parameters of the arrangement viaan appropriate user interface and the computer/processor outputs status,performance and result data (e.g. textual, numerical, graphical, etc.)888 via the user interface.

FIG. 9 is a schematic diagram of an apparatus 900 for measuringpermeability before and after running ERS on the samples in theexperimental setup of described by FIG. 8 . It includes a supply tank910 and a drained water tank 926, inline pump 912 and testing cell 930between them, and inlet pressure gauge 916 and outlet pressure gauge922, as well as a flow meter 924 at the outlet thereof. The cell 930 caninclude a pressurizing liquid pump 918 and a cell pressure gauge 920 tocreate and control higher pressures of pressurizing liquid 919 withinthe cell to provide pressure on the sample 922. A rubber sleeve 922wrapped around the core sample 922 seals the side of the sample from thepressurizing liquid 919. The testing cell can accommodate different coresample lengths. Flow of fluid is controlled by pump 912 and a valve 914.

The experimental setup is adapted to simulate the (HPHT) regime close tothe reservoir conditions, and how the sample (e.g., sample 822) willreact to the ERS process applied thereto. High temperature is achievedby the heater and temperature controller, and the high-pressurecondition is reached by pump and pressurizing fluid pump 918. The twopressure gauges 916, 922 read the pressure data at the inlet and outletstages. The flowmeter 924 provides feedback to control the flow rate atthe pump 912. Several (e.g. K-type) thermocouples can be placed alongthe core sample 822 to read the temperature. All data generated by thesensors, pumps and other devices within the setup and test cell can beinterconnected with the data-acquisition and handling computer (and/orprocessor) 880 running an appropriate software program 882, such asLabView®, which is used for collecting and post-processing of the data884. The computer/processor 880 receives user control inputs 886 toadjust the parameters of the arrangement via an appropriate userinterface and the computer/processor outputs status, performance andresult data (e.g. textual, numerical, graphical, etc.) 888 via the userinterface.

FIG. 10 is a schematic diagram of a pulsed power system, according to atleast one illustrative embodiment. The pulsed power system 1000 which isbased on the principle of parallel charge and parallel discharge of verylow inductance strip line capacitors through suitable spark gap systemswhich can handle peak currents and electrical stresses. It can have 110V or 230 V or higher voltage alternating current as input power andconsists of a filter and DC rectifier 1010 to convert AC to DC, currentcontrol and charger to 1012 store energy in energy storage devices 1014such as capacitor banks, gas dynamic switch 616 such as spark gap todischarge stored capacitor bank energy which can be adjusted fordifferent voltage levels, pulsed forming network (PFN) 1018 to formpulse shapes. The system can be started manually using manual command1030 or it can be attached with a +5 volts command 1028 input to firethe generator. This can also be used to synchronize it with anotherscientific event which will have a +5 volts output pulse. Also, it ispossible to fire the system using more voltage as well, if an attenuatoris built. The trigger generator 1026 will be able to be switched on andoff. This generator should be switched on during operation which isconnected to the switch by trigger transformer 1024. Auxiliary power1020 feeds a real time voltage measurement system 1022, trigger andcommand lines.

In some embodiments, a method comprises injecting electricallyconductive proppant in natural or artificial fractures of reservoir andreleasing electrical energy that propagates through the proppant anddissipates as heat to increase a permeability of the fractures.

In some embodiments, the method further comprises drilling a first wellprior to injecting the electrically conductive proppant.

In some embodiments, the method further comprises mapping a fracturenetwork and fracture size while injecting electrically-conductiveproppant; and drilling a second well at a second well position basedupon the mapped fractured network such that the second well intersectswith the fracture network created by the injecting of theelectrically-conductive proppant.

In some embodiments, the method further comprises placing one or moreelectrodes into one or more wells; and releasing the electrical energyfrom the one or more electrodes.

In some embodiments, the method comprises the releasing electricalenergy comprises emitting an electrical pulse between electrodes; andjoule heating the reservoir.

In some embodiments, the method further comprises thermally shocking thereservoir.

In some embodiments, the method further comprises adjusting one ofelectric energy parameters or injection parameters to control a length,width, or number of artificial fractures.

In some embodiments, the method is described wherein a rock breakdownpressure is reduced by up to 400% or more after releasing the electricalenergy.

In some embodiments, the method is described wherein short-circuitingbetween wells is mitigated by reducing a pressure drop in monitored andtargeted areas in the reservoir under proppant injection andelectro-hydro fracturing operations.

In some embodiments, a method is described wherein the first well is avertical, horizontal, or inclined well (e.g., relative to a direction ofgravity), and is an injection or production well.

In some embodiments, a method is described wherein the second well is avertical, horizontal, or inclined well, and is an injection orproduction well.

In some embodiments, a system comprising a hydraulic fracturing pumpconfigured to inject an electrically conductive proppant into natural orartificial fractures of reservoir and one or more electrodes configuredto release electrical energy that propagates through the electricallyconductive proppant and dissipates as heat to increase a permeability ofthe natural or artificial fractures.

In some embodiments, a system is described wherein the electrical energycomprises at least one of: one or more electrical pulses, or continuouselectricity.

In some embodiments, the system further comprises one or more wellsconfigured to receive the electrically conductive proppant.

In some embodiments, a rock breakdown pressure of the system is reducedby up to 400% or more after releasing the electrical energy.

In some embodiments, a system is described wherein the electricallyconductive proppant comprises calcined coke.

The following examples are intended to illustrate certain embodiments ofthe present invention, but do not exemplify the full scope of theinvention.

EXAMPLE 1

The following example describes the fracturing of a subterraneanreservoir using carbon dioxide (CO₂) as a transport fluid and aconductive proppant.

Table 1 provides several conductive proppants that were tested in thisexample.

TABLE 1 Select Conductive Proppants Tested Tested Size ConductivityPressure temperature conductive proppant [mesh] [S/m] [MPa] [° C.]ceramic particles with 20/40 2000 41 150 a metallic coating petroleumcoke  50/100 5000 27.6 135

Table 2 provides several transport fluids for select hydraulicfracturing compositions.

TABLE 2 Select Transport Fluids Tested Tested Viscosity ConductivityTemperature Pressure fracking fluid [Pa · s] [S/m] [° C.] [MPa] slickwater 1E−3 3.7 75 140 liquefied petroleum 8E−5 — 100.5 70 gas CO2 +polymer 5E−3/ — 25/100 36 2E−3

In order to allow the CO₂ transport fluid to carry the proppant, apolymer was used to thicken the fluid. The hydraulic fracturingcomposition comprising these components functions the same beyond thetesting conditions described in this example. The fluid proppant mixtureconductivity is affected, at least in part, by the proppant conductivityand concentration. These proppants also have the strength to sustain thein situ stress of the reservoir to maintain certain permeability (FIG. 5).

Ceramic proppants may be further divided into three broadclassifications based on their density: namely, lightweight ceramics(LWC), intermediate density ceramics (IDC) and high-density ceramics(HDC). The alumina content of ceramic proppants correlates well with thepellet strength and the proppant density. The approximate correlationbetween alumina content and the mechanical strength of the proppantgrains are of high quality and manufactured in a manner which reducesinternal porosity. LWC typically contains 45-50% alumina; IDC contains70-75% alumina; HDC contains 80-85% alumina. Some proppants are referredto as ultra-high-strength proppant (UHSP) can be rated to 20,000 psi,140 MPa, in crushing strength, and may have a relatively high aluminacontent.

As shown in FIG. 6 , as the volume of conductive proppant within theslurry of the hydraulic fracturing composition increases, the effectiveconductivity of the composition generally increases. Thus, conductiveproppants may increase the conductivity of a reservoir comprising theslurry.

1. A hydraulic fracturing composition, the composition comprising: atransport fluid; and a conductive proppant dispersed in the transportfluid, wherein an electrical conductivity of the hydraulic fracturingcomposition is greater than or equal to 100 S/m.
 2. The composition ofclaim 1, wherein the transport fluid comprises supercritical carbondioxide.
 3. The composition of claim 1, wherein the transport fluidcomprises liquified petroleum.
 4. The composition of claim 1, whereinthe transport fluid comprises water.
 5. The composition of claim 1,wherein the transport fluid comprises a thickening agent.
 6. Thecomposition of claim 1, wherein the transport fluid comprises athickening agent, the thickening agent comprising a polymer.
 7. Thecomposition of claim 1, wherein the conductive proppant comprisespetroleum coke.
 8. The composition of claim 1, wherein the conductiveproppant comprises conductive carbon particles.
 9. The composition ofclaim 1, wherein the conductive proppant comprises ceramic particles.10. The composition of claim 1, wherein the conductive proppantcomprises ceramic particles comprising a metallic coating.
 11. Thecomposition of claim 1, wherein the conductive proppant comprises anelectrically conductive portion and an electrically non-conductiveportion.
 12. The composition of claim 1, wherein the electricalconductivity of the conductive proppant is greater than or equal to 5000S/m.
 13. The composition of claim 1, wherein the conductive proppant hasan average diameter of greater than or equal to 1 μm and/or less than orequal to 1000 μm.
 14. The composition of claim 1, wherein the conductiveproppant comprises alumina.
 15. The composition of claim 1, wherein theconductive proppant has a porosity of greater than or equal to 10%and/or less than or equal to 90%.
 16. The composition of claim 1,wherein the conductive proppant has an average pore diameter of greaterthan or equal to 50 nm and less than or equal to 1000 μm.
 17. Thecomposition of claim 1, wherein the conductive particles are rated towithstand greater than or equal to 30 MPa and/or less than or equal to150 MPa.
 18. A system, comprising: a hydraulic fracturing pumpconfigured to inject a hydraulic fracturing composition into areservoir, wherein the hydraulic fracturing composition comprises atransport fluid and a conductive proppant, wherein an electricalconductivity of the conductive proppant is greater than or equal to 100S/m; and two or more electrodes configured to apply a potential acrossat least a portion of the reservoir.
 19. The system of claim 18, furthercomprising a proppant reservoir containing the hydraulic fracturingcomposition, wherein the proppant reservoir is in fluidic communicationwith the hydraulic fracturing pump.
 20. A method for fracturing areservoir, the method comprising: injecting a hydraulic fracturingcomposition comprising a transport fluid and a conductive proppant intothe reservoir, wherein an electrical conductivity of the conductiveproppant is greater than or equal to 100 S/m; applying a potentialbetween a first portion of the reservoir and a second portion of thereservoir; and fracturing the reservoir between or proximate to thefirst portion and/or the second portion of the reservoir.
 21. The methodof claim 20, further comprising heating the reservoir between and/orproximate to the first portion of the reservoir and/or the secondportion of the reservoir.
 22. The method of claim 20, wherein applyingthe potential across the first portion of the reservoir and the secondportion of the reservoir heats at least a portion of the reservoir. 23.A method for characterizing a reservoir, the method comprising:injecting a hydraulic fracturing composition comprising a transportfluid and a conductive proppant into the reservoir, wherein anelectrical conductivity of the conductive proppant is greater than orequal to 100 S/m; applying electromagnetic radiation to the reservoir;sensing one or more signals related to the applied electromagneticradiation; and determining one or more properties of the reservoir basedat least in part on the one or more signals.
 24. The method of claim 23,wherein determining the property comprises measuring an electricalresistivity of the hydraulic fracturing composition or the transportfluid.
 25. The method of claim 23, further determining an electricalresistivity of portions of the reservoir filled with the hydraulicfracturing composition and determining an electrical resistivity of atleast some portions of the reservoir not filled with the hydraulicfracturing composition.
 26. The method of claim 23, further comprisingmapping a fracture network and/or a fracture size based at least in parton the sensing and/or the determining step.
 27. The method of claim 23,further comprising drilling a second well at a second well positionbased, at least in part, upon the sensing and/or determining steps suchthat the second well intersects with the reservoir.
 28. The method ofclaim 23, further comprising fracturing at least a portion of thereservoir with the hydraulic fracturing composition.
 29. The method ofclaim 23, further comprising injecting a cooling fluid in the reservoir.30. A system for characterizing a reservoir, the system comprising: ahydraulic fracturing pump configured to inject a hydraulic fracturingcomposition into a reservoir, wherein the hydraulic fracturingcomposition comprises a transport fluid and a conductive proppant,wherein an electrical conductivity of the conductive proppant is greaterthan or equal to 100 S/m; two or more electrodes configured to apply apotential across at least a portion of the reservoir; a source ofelectromagnetic radiation; and a sensor configured to receive one ormore signals related to the electromagnetic radiation.